From the 1970s to the 1980s, after the first oil crisis, EOR was developed in the United States with the use of low molecular weight polymers (around 10 million Daltons).
In the 1990s, significant research was carried out into increasing the molecular weights in order to obtain higher viscosities with a low dosage. Today, in this application, the molecular weights are greater than 20 million with high sensitivity to mechanical degradation in that they are injected at a low concentration of 50 to 2,000 ppm.
An oil field comprises between 10 and several thousand secondary recovery water injection wells, the primary recovery method being autogenous oil production.
When a polymer solution is to be injected into a field where water is injected, a concentrated stock solution is first prepared, usually having 0.5 to 2% of a high molecular weight polymer.
This solution is then distributed at 50-2000 parts per million to be injected by various methods.
Usually, within an oil field, a single water injection pump supplies several wells. But because of the heterogeneity of the fields, injection pressures differ from one well to another. For this reason a pressure control or regulating valve at the wellhead is installed (called a choke valve). The polymer solution cannot pass through this choke without degradation, which increases as the pressure falls, in a disproportionate manner from a ΔP of about 20 to 30 bars.
These various types of choke do not allow for the necessary pressure reduction in a polymer solution, without degradation, which becomes almost exponential with increasing pressure.
To remedy this degradation problem, mechanical equipment has been used:                The stock solution and water at low pressure are pumped by a high pressure positive displacement pump at a rate such that the well pressure is maintained;        The water and the polymer at the final pressure are mixed at high pressure, this solution passing through a calibrated tube of suitable length thus creating the necessary pressure reduction without degrading the polymer. In this equipment, the degradation with pressure differences of 50 bars, the speed of the solution with a standard concentration of 1000-2000 ppm and a molecular weight of 20 million should not exceed about 11 m/s (U.S. patent 2015/0041143);        The mixture may also be passed through a positive displacement pump, for example a gear-driven pump, whose speed and therefore flow are controlled by a hydraulic or electric brake.        
In the 1980s, Marathon filed two patents that are interesting in principle but not very adaptable to current field conditions:                U.S. Pat. No. 4,782,847 uses a needle valve and tube sections with restrictions that give rise to the Vortex effect. Tests conducted with oil companies on low viscosity (<20 cps) dilute solutions (1000 ppm) of polymers having molecular weights of 20 million allowed the needle valve to reduce the pressure by 7 to 10 bars with a degradation of no more than 2%. The Vortex orifices and the needle valve do not allow for permanent adjustment at a well where the variation over time can be 50 bars. The system must therefore be dismantled in order to adjust the vortex sleeves, which is not possible in large fields.        U.S. Pat. No. 4,510,993 uses a single needle valve or needle compensation system, but has more important limitations than the above patent.        
An oil company currently requires:                A degradation at 50 bars of a maximum of 10% of the viscosity (sometimes 5%);        With viscosities in the range of 3 to 30 cps much more degradable than concentrated solutions;        With polymer concentrations from 50 to 2000 ppm giving widely varying viscosity due to the effect of the salinity on the viscosity.        
Today, there are fields using more than 50,000 ppm of NaCl:                With equipment not requiring dismantling for many years (an EOR can last from 10 to 20 years);        The variation in pressure can be implemented in a very simple manner at the wellhead;        And a pressure variation at a well of at least 50 bars.        
These are conditions which did not exist in the 1980s and it would be illusory today to use a needle valve or an in-line piston and needle valve as described in U.S. Pat. No. 4,553,594.
To compensate for the problems of the prior art, the Assignee has developed a system based upon multiple gate or needle valves each separated by straight lengths of tube.